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eto-20201112

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


November 12, 2020
Date of Report (Date of earliest event reported)

ENERGY TRANSFER OPERATING, L.P.
(Exact name of Registrant as specified in its charter)

Delaware	1-31219	73-1493906
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

8111 Westchester Drive, Suite 600

Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETPprC

New York Stock Exchange

7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETPprD

New York Stock Exchange

7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETPprE

New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Item 8.01. Other Events.

This Current Report on Form 8-K is being filed principally to reflect retrospective revisions that have been made to the consolidated financial statements and certain related information of Energy Transfer Operating, L.P. ("ETO" or the "Partnership") that were filed with the Securities and Exchange Commission ("SEC") by the Partnership on February 21, 2020 as Items 1, 1A, 6, 7 and 8 to its Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”).

Energy Transfer LP ("ET") completed the acquisition of SemGroup ("SemGroup") in December 2019. ETO is a consolidated subsidiary of ET. As disclosed in our Quarterly Report on Form 10-Q for the period ended September 30, 2020, filed on November 5, 2020, ET contributed SemGroup and its former subsidiaries to ETO during the first and second quarters of 2020.

In addition, effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the previous accounting policy, all crude oil barrels were recorded as inventory under the weighted-average cost method. Under the revised accounting policy, barrels related to pipeline linefill and tank bottoms are accounted for as long-lived assets and reflected as non-current assets on the consolidated balance sheet.

The consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” have been updated to reflect material subsequent events that have occurred after the date the consolidated financial statements were originally issued. As further discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Exhibit 99.1, that item has been updated solely to reflect the changes discussed above. No attempt has been made to modify or update other disclosures in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” (included in Exhibit 99.1) to reflect events or occurrences after the date of the filing of the 2019 Form 10-K, February 21, 2020.

Item 9.01 of this Current Report on Form 8-K revises certain information contained in ETO’s 2019 Form 10-K to reflect these retrospective revisions. In particular, Exhibit 99.1 contains revised financial statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 9.01 Financial Statements and Exhibits.

See the Exhibit Index set forth below for a list of exhibits included with this Form 8-K.


Exhibit Number			Description



99.1			Revised Energy Transfer Operating, L.P. financial statements as of December 31, 2019 and 2018, and for each of the three years in the period ended December 31, 2019, and Management's Discussion and Analysis of Financial Condition and Results of Operations.
101*			Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018; (ii) our Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017; (iii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017; (iv) our Consolidated Statement of Partners’ Capital for the years ended December 31, 2019, 2018 and 2017; (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017; and (vi) the notes to our Consolidated Financial Statements.
104			Cover Page Interactive Data File (embedded within the Inline XBRL document)

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


		ENERGY TRANSFER OPERATING, L.P.

		By:	Energy Transfer Partners GP, L.P.,
			its general partner

		By:	Energy Transfer Partners, L.L.C.,
			its general partner

Date:	November 12, 2020	By:	/s/ Thomas E. Long
			Thomas E. Long
			Chief Financial Officer

Document

Table of Contents

TABLE OF CONTENTS


		PAGE














PART II



ITEM 6.	SELECTED FINANCIAL DATA	6

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	7



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	56

Table of Contents

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Operating, L.P. (the “Partnership,” or “ETO”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Item 1A. Risk Factors” included in this annual report.

Definitions

The following is a list of certain acronyms and terms used throughout this document:


			/d						per day

			AOCI						accumulated other comprehensive income (loss)

			AROs						asset retirement obligations

			Bbls						barrels

			BBtu						billion British thermal units

			Bcf						billion cubic feet

			Btu						British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used

			Capacity						capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

			CDM						CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively

			Citrus						Citrus, LLC



			Dakota Access						Dakota Access, LLC, a less than wholly-owned subsidiary of ETO

			DOE						United States Department of Energy

			DOJ						United States Department of Justice

			DOT						United States Department of Transportation

			EPA						United States Environmental Protection Agency

			ET						Energy Transfer LP, the parent company of ETO





			ETC OLP						La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company and is a wholly-owned subsidiary of ETO

			ETC Sunoco						ETC Sunoco Holdings LLC (formerly, Sunoco Inc.), a wholly-owned subsidiary of ETO

			ETC Tiger						ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of ETO

			ETCO						Energy Transfer Crude Oil Company, LLC, a less than wholly-owned subsidiary of ETO









			ETP GP						Energy Transfer Partners GP, L.P., the general partner of ETO

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			ETP Holdco						ETP Holdco Corporation, a wholly owned subsidiary of ETO

			ETP LLC						Energy Transfer Partners, L.L.C., the general partner of ETP GP

			Exchange Act						Securities Exchange Act of 1934, as amended

			ExxonMobil						Exxon Mobil Corporation

			FEP						Fayetteville Express Pipeline LLC

			FERC						Federal Energy Regulatory Commission

			FGT						Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus

			GAAP						accounting principles generally accepted in the United States of America

			Gulf States						Gulf States Transmission LLC, a wholly-owned subsidiary of ETO

			HFOTCO						Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal

			HPC						RIGS Haynesville Partnership Co., a wholly-owned subsidiary of ETO

			IDRs						incentive distribution rights

			KMI						Kinder Morgan Inc.

			Lake Charles LNG						Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC), a wholly-owned subsidiary of ETO

			LCL						Lake Charles LNG Export Company, LLC, a wholly-owned subsidiary of ETO



			LIBOR						London Interbank Offered Rate

			LNG						liquefied natural gas

			Lone Star						Lone Star NGL LLC, a wholly-owned subsidiary of ETO



			MBbls						thousand barrels

			MEP						Midcontinent Express Pipeline LLC

			Mi Vida JV						Mi Vida JV LLC

			Mid-Valley						Mid-Valley Pipeline Company, a wholly-owned subsidiary of ETO

			MMBls						million barrels

			MMcf						million cubic feet

			MTBE						methyl tertiary butyl ether

			NGL						natural gas liquid, such as propane, butane and natural gasoline

			NYMEX						New York Mercantile Exchange

			NYSE						New York Stock Exchange

			ORS						Ohio River System LLC, a less than wholly-owned subsidiary of ETO

			OSHA						federal Occupational Safety and Health Act

			OTC						over-the-counter

			Panhandle						Panhandle Eastern Pipe Line Company, LP and its subsidiaries, wholly-owned by ETO

			PCBs						polychlorinated biphenyls

			PennTex						PennTex Midstream Partners, LP, acquired by ETO during 2016-2017 and now a wholly-owned subsidiary named ETC PennTex LLC

			PEP						Permian Express Partners LLC, a less than wholly-owned subsidiary of ETO

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			PES						Philadelphia Energy Solutions Refining and Marketing LLC, non-controlling interest owned by ETO

			Phillips 66						Phillips 66 Partners LP

			PHMSA						Pipeline Hazardous Materials Safety Administration

			Preferred Unitholders						Unitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units and Series G Preferred Units, collectively

			Ranch JV						Ranch Westex JV LLC

			Regency						Regency Energy Partners LP, a wholly-owned subsidiary of ETO

			Retail Holdings						ETP Retail Holdings, LLC, a wholly-owned subsidiary of ETO



			RIGS						Regency Intrastate Gas System, a wholly-owned subsidiary of ETO

			Rover						Rover Pipeline LLC, a less than wholly-owned subsidiary of ETO

			Sea Robin						Sea Robin Pipeline Company, LLC, a wholly-owned subsidiary of Panhandle

			SEC						Securities and Exchange Commission

			SemCAMS						SemCAMS Midstream ULC, a less than wholly-owned subsidiary of ETO

			SemGroup						SemGroup Corporation

			Series A Preferred Units						6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			Series B Preferred Units						6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			Series C Preferred Units						7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			Series D Preferred Units						7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			Series E Preferred Units						7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			Series F Preferred Units						6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

			Series G Preferred Units						7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

			Shell						Royal Dutch Shell plc

			Southwest Gas						Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage Company)

			SPLP						Sunoco Pipeline L.P., a wholly-owned subsidiary of ETO



			Sunoco Logistics						Sunoco Logistics Partners L.P., a wholly-owned subsidiary of ETO

			Sunoco (R&M)						Sunoco (R&M), LLC







			Transwestern						Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETO

			TRRC						Texas Railroad Commission

			Trunkline						Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle

			Unitholders						Preferred Unitholders and our common unitholder (Energy Transfer LP), collectively

			USAC						USA Compression Partners, LP, a wholly-owned subsidiary of ETO

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Adjusted EBITDA is a term used throughout this document, which we define as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

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PART II

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and the accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.

As discussed in Note 1 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the Energy Transfer Merger resulted in the retrospective adjustment to consolidate Sunoco LP and Lake Charles LNG for all periods presented and USAC beginning April 2, 2018.

As discussed in Note 1 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the merger of legacy ETO (the entity named Energy Transfer Partners, L.P. prior to the merger) and legacy Sunoco Logistics in April 2017 resulted in legacy ETO being treated as the surviving entity from an accounting perspective.

As discussed in Note 2 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the Partnership’s consolidated financial statements for all periods presented have been retrospectively adjusted to reflect the change in the accounting policy related to certain barrels of crude oil.

As discussed in Note 3 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the sale and contribution transactions resulted in the retrospective adjustment to consolidate SemGroup and its former subsidiaries beginning December 5, 2019. Accordingly, the selected financial data below reflects the consolidated financial information of legacy ETO, adjusted for the effects of the events above.


	Years Ended December 31,
	2019		2018		2017		2016		2015
Statement of Operations Data:
Total revenues	$	54,213	$	54,087	$	40,523	$	31,792	$	36,096
Operating income	7,222		5,457		2,714		1,933		2,410
Income from continuing operations	5,115		4,094		2,901		869		1,440
Balance Sheet Data (at period end):
Assets held for sale	—		—		3,313		3,588		3,681
Total assets	102,294		88,609		86,596		79,147		71,322
Liabilities associated with assets held for sale	—		—		75		48		42
Long-term debt, less current maturities	50,904		37,853		36,971		36,251		30,505
Total equity	37,425		36,788		37,079		29,101		30,173
Other Financial Data:
Capital expenditures:
Maintenance (accrual basis) (1)	658		510		479		474		550
Growth (accrual basis) (1)	4,610		5,120		5,601		5,775		8,046
Cash paid for acquisitions	257		429		583		1,398		964

(1)Maintenance and growth capital expenditures include Sunoco LP’s capital expenditures related to discontinued operations for the years ended December 31, 2016 and 2015.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts, except per unit data, are in millions)

In order to preserve the nature and character of the disclosures set forth in the 2019 Form 10-K, the items included in this “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” have been updated solely to reflect ETO’s change in its accounting policy related to certain barrels of crude oil and the retrospective consolidation of SemGroup, as further discussed below and in “Item 8. Financial Statements and Supplementary Data” included elsewhere in this Exhibit 99.1. No attempt has been made to modify or update other disclosures in this “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” to reflect events or occurrences after the date of the filing of the 2019 Form 10-K, February 21, 2020. Therefore, this “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” should be read in conjunction with the 2019 Form 10-K, and filings made by ETO with the SEC subsequent to the filing of the 2019 Form 10-K, including ETO’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2020, June 30, 2020 and September 30, 2020 filed on May 11, 2020, August 6, 2020 and November 5, 2020.

This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” included in this report.

References to “we,” “us,” “our,” the “Partnership” and “ETO” shall mean Energy Transfer Operating, L.P. and its subsidiaries.

Overview

The primary activities and operating subsidiaries through which we conduct those activities are as follows:

•natural gas operations, including the following:

•natural gas midstream and intrastate transportation and storage;

•interstate natural gas transportation and storage; and

•crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are publicly traded master limited partnerships.

Recent Developments

Series F and Series G Preferred Units Issuance

On January 22, 2020, ETO issued 500,000 of its 6.750% Series F Preferred Units at a price of $1,000 per unit and 1,100,000 of its 7.125% Series G Preferred Units at a price of $1,000 per unit. The net proceeds were used to repay amounts outstanding under ETO’s revolving credit facility and for general partnership purposes.

ETO January 2020 Senior Notes Offering and Redemption

On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of the Partnership’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of the Partnership’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis.

Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

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ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P.

As of December 31, 2019, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 2.78%.

SemGroup Acquisition

In December 2019, ET completed the acquisition of SemGroup. ET contributed SemGroup and its former subsidiaries to ETO through sale and contribution transactions in 2020. The contribution transactions were accounted for as reorganizations of entities under common control; therefore, the contributed entities’ assets and liabilities were not adjusted as of the contribution date.

JC Nolan Pipeline

On July 1, 2019, ETO and Sunoco LP entered into a joint venture on the JC Nolan diesel fuel pipeline to West Texas and the JC Nolan terminal. ETO operates the pipeline for the joint venture, which transports diesel fuel from Hebert, Texas to a terminal in the Midland, Texas area. The diesel fuel pipeline has an initial capacity of 30,000 barrels per day and was successfully commissioned in August 2019.

Series E Preferred Units Issuance

In April 2019, ETO issued 32 million of its 7.600% Series E Preferred Units at a price of $25 per unit, including 4 million Series E Preferred Units pursuant to the underwriters’ exercise of their option to purchase additional preferred units. The total gross proceeds from the Series E Preferred Unit issuance were $800 million, including $100 million from the underwriters’ exercise of their option to purchase additional preferred units. The net proceeds were used to repay amounts outstanding under ETO’s revolving credit facility and for general partnership purposes.

ET-ETO Senior Notes Exchange

In March 2019, ETO issued approximately $4.21 billion aggregate principal amount of senior notes to settle and exchange approximately 97% of ET’s outstanding senior notes. In connection with this exchange, ETO issued $1.14 billion aggregate principal amount of 7.50% senior notes due 2020, $995 million aggregate principal amount of 4.25% senior notes due 2023, $1.13 billion aggregate principal amount of 5.875% senior notes due 2024 and $956 million aggregate principal amount of 5.50% senior notes due 2027.

ETO 2019 Senior Notes Offering and Redemption

In January 2019, ETO issued $750 million aggregate principal amount of 4.50% senior notes due 2024, $1.50 billion aggregate principal amount of 5.25% senior notes due 2029 and $1.75 billion aggregate principal amount of 6.25% senior notes due 2049. The $3.96 billion net proceeds from the offering were used to repay in full ET’s outstanding senior secured term loan, to redeem outstanding senior notes, to repay a portion of the borrowings under the Partnership’s revolving credit facility and for general partnership purposes.

Panhandle Senior Notes Redemption

In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.

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Bakken Senior Notes Offering

In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, issued $650 million aggregate principal amount of 3.625% senior notes due 2022, $1.00 billion aggregate principal amount of 3.90% senior notes due 2024 and $850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.

Sunoco LP Senior Notes Offering

In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms.

USAC Senior Notes Offering

In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior notes due 2027 in a private placement, and in December 2019, USAC exchanged those notes for substantially identical senior notes registered under the Securities Act. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.

Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective January 2018, the 2017 Tax and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. In light of the rehearing order, the impacts of the FERC’s policy on the treatment of income taxes may have on the rates ETO can charge for the FERC-regulated transportation services are unknown at this time.

The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) on March 15, 2018, requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or before May 21, 2018.

In March 2019, following the decision of the D.C. Circuit in Emera Maine v. Federal Energy Regulatory Commission, the FERC issued a Notice of Inquiry regarding its policy for determining return on equity (“ROE”). The FERC specifically sought information and stakeholder views to help the FERC explore whether, and if so how, it should modify its policies concerning the determination of ROE to be used in designing jurisdictional rates charged by public utilities. The FERC also expressly sought comment on whether any changes to its policies concerning public utility ROEs should be applied to interstate natural gas and oil pipelines. Initial comments were due in June 2019, and reply comments were due in July 2019. The FERC has not taken any further action with respect to the Notice of Inquiry as of this time, and therefore we cannot predict what effect, if any, such development could have on our cost-of-service rates in the future.

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Also included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC-regulated natural gas pipeline select one of four options to address changes to the pipeline’s revenue requirements as a result of the tax reductions: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates to reflect the reduced tax rates, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. For the limited NGA Section 4 option, the FERC clarified that, notwithstanding the Revised Policy Statement, a pipeline organized as a master limited partnership does not need to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Trunkline, ETC Tiger Pipeline, LLC and Panhandle filed their respective FERC Form No. 501-Gs on October 11, 2018. FEP, Lake Charles LNG and certain other operating subsidiaries filed their respective FERC Form No. 501-Gs on or about November 8, 2018, and Rover, FGT, Transwestern and MEP filed their respective FERC Form No. 501-Gs on or about December 6, 2018.

By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle filed a cost and revenue study on April 1, 2019. Panhandle filed a NGA Section 4 rate case on August 30, 2019.

By order issued October 1, 2019, the Panhandle Section 5 and Section 4 cases were consolidated. An initial decision is expected to be issued in the first quarter of 2021. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. The settlement was approved on October 29, 2019.

Sea Robin Pipeline Company filed a Section 4 rate case on November 30, 2018. A procedural schedule was ordered with a hearing date in the 4th quarter of 2019. Sea Robin Pipeline Company has reached a settlement of this proceeding, with a settlement filed July 22, 2019. The settlement was approved by the FERC by order dated October 17, 2019.

Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, the FERC or our shippers may challenge the cost of service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. The revenues we receive from natural gas transportation services we provide pursuant to cost of service based rates may decrease in the future as a result of the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost of service rates, if any, will depend on a detailed review of all of ETO’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.

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Pipeline Certification

The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Common Carrier Regulation

The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by the FERC in its next five year review of the liquids pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of the appropriate pipeline index. Accordingly, depending on the FERC’s application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates.

Trends and Outlook

We anticipate continued earnings growth in 2020 from the recently completed projects, as well as our current project backlog. We also continue to seek asset optimization opportunities through strategic transactions among us and our subsidiaries and/or affiliates, and we expect to continue to evaluate and execute on such opportunities. As we have in the past, we will evaluate growth projects and acquisitions as such opportunities may be identified in the future, and we believe that the current capital markets are conducive to funding such future projects.

With respect to commodity prices, natural gas prices have remained comparatively low in recent months as associated gas from shale oil resources has provided additional supply to the market, increasing domestic supply to highs above 100 Bcf/d. Global oil and natural gas demand growth is likely to continue into the foreseeable future and will support U.S. production increases and, in turn U.S. natural gas export projects to Mexico as well as LNG exports.

For crude oil, new pipelines that came online during 2019 have resulted in Permian barrels now pricing closer to other regional hubs, which is a departure from the substantial discounts seen a year ago. These pipelines have enabled Permian producers to realize higher crude oil revenues, supporting continued growth in the region. Crude oil exports from the U.S. are continuing to increase as a result, providing additional opportunity for U.S. midstream sector growth.

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Results of Operations

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.

As discussed in Note 1 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data,” the Energy Transfer Merger in October 2018 resulted in the retrospective adjustment of the Partnership’s consolidated financial statements to reflect consolidation beginning January 1, 2017 of Sunoco LP and Lake Charles LNG and April 2, 2018 for USAC.

As discussed in Note 1 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data,” the merger of legacy ETO (the entity named Energy Transfer Partners, L.P. prior to the merger) and legacy Sunoco Logistics in April 2017 resulted in legacy ETO being treated as the surviving entity from an accounting perspective.

As discussed in Note 3 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the sale and contribution transactions resulted in the retrospective adjustment to consolidate SemGroup and its former subsidiaries beginning December 5, 2019. Accordingly, the financial data below reflects the consolidated financial information of legacy ETO.

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Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Consolidated Results


	Years Ended December 31,
	2019		2018		Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	999	$	927	$	72
Interstate transportation and storage	1,792		1,680		112
Midstream	1,602		1,627		(25)
NGL and refined products transportation and services	2,666		1,979		687
Crude oil transportation and services	2,898		2,385		513
Investment in Sunoco LP	665		638		27
Investment in USAC	420		289		131
All other	106		76		30
Total Segment Adjusted EBITDA	11,148		9,601		1,547
Depreciation, depletion and amortization	(3,136)		(2,843)		(293)
Interest expense, net of interest capitalized	(2,262)		(1,709)		(553)
Impairment losses	(74)		(431)		357
Gains (losses) on interest rate derivatives	(241)		47		(288)
Non-cash compensation expense	(113)		(105)		(8)
Unrealized losses on commodity risk management activities	(5)		(11)		6
Inventory valuation adjustments	79		(85)		164
Losses on extinguishments of debt	(2)		(109)		107
Adjusted EBITDA related to unconsolidated affiliates	(626)		(655)		29
Equity in earnings of unconsolidated affiliates	302		344		(42)
Adjusted EBITDA related to discontinued operations	—		25		(25)
Other, net	244		30		214
Income from continuing operations before income tax expense	5,314		4,099		1,215
Income tax expense from continuing operations	(199)		(5)		(194)
Income from continuing operations	5,115		4,094		1,021
Loss from discontinued operations, net of income taxes	—		(265)		265
Net income	$	5,115	$	3,829	$	1,286

Adjusted EBITDA (consolidated). For the year ended December 31, 2019 compared to the prior year, Adjusted EBITDA increased approximately $1.55 billion, or 16%. The increase was primarily due to the impact of multiple revenue-generating assets being placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets and acquisitions was approximately $784 million, of which the largest increases were from increased volumes to our Mariner East pipeline and terminal assets due to the addition of pipeline capacity in the fourth quarter of 2018 (a $274 million impact to the NGL and refined products transportation and services segment), the commissioning of our fifth and sixth fractionators (a $131 million impact to the NGL and refined products transportation and services segment), the ramp up of volumes on our Bayou Bridge system due to placing phase II in service in the second quarter of 2019 (a $60 million impact to our crude oil transportation and services segment), the Rover pipeline (a $78 million impact to the interstate transportation and storage segment), the addition of gas processing capacity to our Arrowhead gas plant (a $31 million impact to our midstream segment), placing our Permian Express 4 pipeline in service in October 2019 (a $26 million impact to our crude oil transportation and services segment) and the acquisition of USAC (a net impact of $131 million among the investment in USAC and all other segments). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, particularly due to increased throughput on our Bakken Pipeline system as well as increased production in the Permian, which impacted multiple segments. Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.

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Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased primarily due to additional depreciation from assets recently placed in service and recent acquisitions.

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased during the year ended December 31, 2019 compared to the prior year primarily due to the following:

•an increase of $475 million recognized by the Partnership (excluding Sunoco LP and USAC) primarily related to an increase in long-term debt, which included $4.2 billion of senior notes issued in the ET-ETO senior note exchange (discussed below under “Description of Indebtedness”), as well as additional senior note issuances and borrowings under our revolving credit facilities;

•an increase of $49 million recognized by USAC primarily attributable to higher overall debt balances and higher interest rates on borrowings under the credit agreement. These increases were partially offset by the decrease in borrowings under the credit agreement; and

•an increase of $29 million recognized by Sunoco LP due to an increase in total long-term debt.

Impairment Losses. During the year ended December 31, 2019, the Partnership recognized goodwill impairments of $12 million related to the Southwest Gas operations within the interstate transportation and storage segment and $9 million related to our North Central operations within the midstream segment, both of which were primarily due to changes in assumptions related to projected future revenues and cash flows. Also during the year ended December 31, 2019, Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York, and USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets.

During the year ended December 31, 2018, the Partnership recognized goodwill impairments of $378 million and asset impairments of $4 million related to our midstream operations and asset impairments of $9 million related to idle leased assets in our crude operations. Sunoco LP recognized a $30 million indefinite-lived intangible asset impairment related to contractual rights. USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.

Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the year ended December 31, 2019 resulted from a decrease in forward interest rates and gains in 2018 resulted from an increase in forward interest rates.

Unrealized Losses on Commodity Risk Management Activities. The unrealized losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 13 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP primarily driven by changes in fuel prices between periods.

Losses on Extinguishments of Debt. Amounts were related to Sunoco LP’s senior note and term loan redemption in January 2018.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.

Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that were disposed of in January 2018.

Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax Expense. For the year ended December 31, 2019 compared to the prior year, income tax expense increased due to an increase in income at our corporate subsidiaries and the recognition of a favorable state tax rate change in the prior period.

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Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:


	Years Ended December 31,
	2019		2018		Change
Equity in earnings of unconsolidated affiliates:
Citrus	$	148	$	141	$	7
FEP	59		55		4
MEP	15		31		(16)
Other	80		117		(37)
Total equity in earnings of unconsolidated affiliates	$	302	$	344	$	(42)

Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus	$	342	$	337	$	5
FEP	75		74		1
MEP	60		81		(21)
Other	149		163		(14)
Total Adjusted EBITDA related to unconsolidated affiliates	$	626	$	655	$	(29)

Distributions received from unconsolidated affiliates:
Citrus	$	178	$	171	$	7
FEP	73		68		5
MEP	36		48		(12)
Other	101		110		(9)
Total distributions received from unconsolidated affiliates	$	388	$	397	$	(9)

(1)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:

•Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.

•Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

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•Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

For additional information regarding our business segments, see “Item 1. Business” and Notes 1 and 16 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

Segment Operating Results

Intrastate Transportation and Storage


	Years Ended December 31,
	2019		2018		Change
Natural gas transported (BBtu/d)	12,442		10,873		1,569
Revenues	$	3,099	$	3,737	$	(638)
Cost of products sold	1,909		2,665		(756)
Segment margin	1,190		1,072		118
Unrealized losses on commodity risk management activities	2		38		(36)
Operating expenses, excluding non-cash compensation expense	(190)		(189)		(1)
Selling, general and administrative expenses, excluding non-cash compensation expense	(29)		(27)		(2)
Adjusted EBITDA related to unconsolidated affiliates	25		32		(7)
Other	1		1		—
Segment Adjusted EBITDA	$	999	$	927	$	72

Volumes. For the year ended December 31, 2019 compared to the prior year, transported volumes increased primarily due to the impact of reflecting RIGS as a consolidated subsidiary beginning April 2018 and the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.

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Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:


	Years Ended December 31,
	2019		2018		Change
Transportation fees	$	614	$	525	$	89
Natural gas sales and other (excluding unrealized gains and losses)	505		510		(5)
Retained fuel revenues (excluding unrealized gains and losses)	50		59		(9)
Storage margin, including fees (excluding unrealized gains and losses)	23		16		7
Unrealized losses on commodity risk management activities	(2)		(38)		36
Total segment margin	$	1,190	$	1,072	$	118

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:

•an increase of $64 million in transportation fees, excluding the impact of consolidating RIGS beginning April 2018 as discussed below, primarily due to the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;

•a net increase of $11 million primarily due to the consolidation of RIGS beginning April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million and $6 million, respectively, partially offset by a decrease in Adjusted EBITDA related to unconsolidated affiliates of $9 million; and

•an increase of $7 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018 and higher storage fees, partially offset by a $20 million decrease due to lower physical withdrawals; partially offset by

•a decrease of $9 million in retained fuel revenues primarily due to lower gas prices; and

•a decrease of $5 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity.

Interstate Transportation and Storage


	Years Ended December 31,
	2019		2018		Change
Natural gas transported (BBtu/d)	11,346		9,542		1,804
Natural gas sold (BBtu/d)	17		17		—
Revenues	$	1,963	$	1,682	$	281
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(569)		(431)		(138)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(72)		(63)		(9)
Adjusted EBITDA related to unconsolidated affiliates	477		492		(15)
Other	(7)		—		(7)
Segment Adjusted EBITDA	$	1,792	$	1,680	$	112

Volumes. For the year ended December 31, 2019 compared to the prior year, transported volumes increased as a result of the addition of new contracted volumes for delivery out of the Haynesville Shale, higher volumes on our Rover pipeline as a result of the full year availability of new supply connections, and higher throughput on Trunkline and Panhandle due to increased utilization of higher contracted capacity.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:

•an increase in margin of $231 million from the Rover pipeline due to higher reservation and usage resulting from additional connections and utilization of additional compression;

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•an increase of $40 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Transwestern, Tiger and Panhandle Eastern systems; and

•an increase of $6 million from the Sea Robin pipeline due to higher rates resulting from the rate case filed in June 2019, as well as fewer third party supply interruptions on the Sea Robin system; partially offset by

•an increase of $138 million in operating expense primarily due to an increase in ad valorem taxes of $126 million on the Rover pipeline system resulting from placing the final portions of this asset into service in November 2018, an increase of $24 million in transportation expense on Rover due to an increase in transportation volumes, an increase of $5 million in allocated overhead costs and additional operating expense of $4 million for assets acquired in June 2019, partially offset by lower gas imbalance and system gas activity of $15 million and lower storage capacity leased on the Panhandle Eastern system of $8 million;

•an increase of $9 million in selling, general and administrative expenses primarily due to an increase in insurance expense of $8 million, an increase in employee cost of $4 million, and an increase in allocated overhead costs of $3 million, partially offset by lower Ohio excise tax on our Rover system; and

•a decrease of $15 million in adjusted EBITDA related to unconsolidated affiliates primarily resulting from a $20 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted at lower rates on expiring contracts, partially offset by a $5 million increase from our Citrus joint venture as we brought new volumes to the system in 2019.

Midstream


	Years Ended December 31,
	2019		2018		Change
Gathered volumes (BBtu/d)	13,460		12,126		1,334
NGLs produced (MBbls/d)	571		540		31
Equity NGLs (MBbls/d)	31		29		2
Revenues	$	6,031	$	7,522	$	(1,491)
Cost of products sold	3,577		5,145		(1,568)
Segment margin	2,454		2,377		77

Operating expenses, excluding non-cash compensation expense	(791)		(705)		(86)
Selling, general and administrative expenses, excluding non-cash compensation expense	(90)		(81)		(9)
Adjusted EBITDA related to unconsolidated affiliates	27		33		(6)
Other	2		3		(1)
Segment Adjusted EBITDA	$	1,602	$	1,627	$	(25)

Volumes. For the year ended December 31, 2019 compared to the prior year, gathered volumes increased primarily due to increases in the Northeast, Permian, Ark-La-Tex, South Texas and North Texas regions. NGL production increased due to increases in the Permian and North Texas regions partially offset by ethane rejection in the South Texas region.

Segment Margin. The table below presents the components of our midstream segment margin. For the year ended December 31, 2018, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees from fee-based margin to non-fee-based margin in order to conform to the current period classification.


	Years Ended December 31,
	2019		2018		Change
Gathering and processing fee-based revenues	$	2,002	$	1,788	$	214
Non-fee based contracts and processing	452		589		(137)

Total segment margin	$	2,454	$	2,377	$	77

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Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:

•a decrease of $137 million in non fee-based margin due to lower NGL prices of $131 million and lower gas prices of $58 million, offset by an increase of $51 million in non fee-based margin due to increased throughput volume in North Texas, South Texas and Permian regions;

•an increase of $86 million in operating expenses due to increases of $33 million in outside services, $29 million in maintenance project costs, $17 million in employee costs and $6 million in office expenses and materials; and

•an increase of $9 million in selling, general and administrative expenses primarily due to a decrease of $5 million in capitalized overhead and an increase of $4 million in insurance expense; partially offset by

•an increase of $214 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions.

NGL and Refined Products Transportation and Services


	Years Ended December 31,
	2019		2018		Change
NGL transportation volumes (MBbls/d)	1,289		1,027		262
Refined products transportation volumes (MBbls/d)	583		621		(38)
NGL and refined products terminal volumes (MBbls/d)	944		812		132
NGL fractionation volumes (MBbls/d)	706		527		179
Revenues	$	11,641	$	11,123	$	518
Cost of products sold	8,393		8,462		(69)
Segment margin	3,248		2,661		587
Unrealized (gains) losses on commodity risk management activities	81		(86)		167
Operating expenses, excluding non-cash compensation expense	(656)		(604)		(52)
Selling, general and administrative expenses, excluding non-cash compensation expense	(93)		(74)		(19)
Adjusted EBITDA related to unconsolidated affiliates	86		82		4

Segment Adjusted EBITDA	$	2,666	$	1,979	$	687

Volumes. For the year ended December 31, 2019 compared to the prior year, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. In addition, NGL transportation volumes on our Northeast assets increased due to the initiation of service on the Mariner East 2 pipeline system.

Refined products transportation volumes decreased for the year ended December 31, 2019 compared to prior year due to the closure of a third party refinery during the third quarter of 2019, negatively impacting supply to our refined products transportation system. These decreases in volumes are partially offset by the initiation of service on the JC Nolan Pipeline in the third quarter of 2019.

NGL and refined products terminal volumes increased for the year ended December 31, 2019 compared to the prior year primarily due to the initiation of service on our Mariner East 2 pipeline system which commenced operations in the fourth quarter of 2018.

Average volumes fractionated at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2019 compared to the prior year primarily due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively.

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Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:


	Years Ended December 31,
	2019		2018		Change
Fractionators and refinery services margin	$	664	$	511	$	153
Transportation margin	1,716		1,233		483
Storage margin	223		211		12
Terminal Services margin	630		494		136
Marketing margin	96		126		(30)
Unrealized gains (losses) on commodity risk management activities	(81)		86		(167)
Total segment margin	$	3,248	$	2,661	$	587

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

•an increase of $483 million in transportation margin primarily due to a $265 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $212 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $29 million increase due to higher throughput volumes from the Barnett region, a $9 million increase from the Eagle Ford region, and a $9 million increase due to the initiation of service on the JC Nolan Pipeline. These increases were partially offset by a $21 million decrease resulting from Mariner East 1 pipeline downtime, a $13 million decrease due to the closure of a third-party refinery during the third quarter of 2019, negatively impacting refined product supply to our system, and a $5 million decrease due to the timing of deficiency fees on Mariner West;

•an increase of $153 million in fractionation and refinery services margin primarily due to a $167 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a reclassification between our fractionation and storage margins;

•an increase of $136 million in terminal services margin primarily due to a $171 million increase from the initiation of service of our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018 and a $7 million increase due to increased tank lease revenue from third-party customers. These increases were partially offset by a $16 million decrease in volumes and expense reimbursements from third parties on Mariner East 1, a $16 million decrease due to lower volumes from third party pipeline, truck and rail deliveries into our Marcus Hook terminal, a $5 million decrease due to fewer vessels exported out of our Nederland terminal, and a $4 million decrease due to the closure of a third party refinery during the third quarter of 2019; and

•an increase of $12 million in storage margin primarily due to a reclassification between our storage and fractionation margins; partially offset by

•a decrease of $30 million in marketing margin primarily due to capacity lease fees incurred by our marketing affiliate on our Mariner East 2 pipeline, offset by increased gains from our butane blending business due to more favorable market conditions and increased volumes, as well as increased optimization gains from the sale of NGL component products at our Mont Belvieu facility;

•an increase of $52 million in operating expenses primarily due to a $26 million increase in employee and ad valorem tax expenses on our terminals, fractionation, and transportation operations, a $14 million increase in utility costs to operate our pipelines and our fifth and sixth fractionators which commenced July 2018 and February 2019, respectively, and an $8 million increase in maintenance project costs due to the timing of multiple projects on our transportation assets; and

•an increase of $19 million in general and administrative expenses primarily due to a $10 million increase in allocated overhead costs, a $5 million increase in insurance expenses, a $4 million increase in legal fees, and a $2 million increase in employee costs.

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Crude Oil Transportation and Services


	Years Ended December 31,
	2019		2018		Change
Crude transportation volumes (MBbls/d)	4,662		4,172		490
Crude terminals volumes (MBbls/d)	2,068		2,096		(28)
Revenue	$	18,447	$	17,332	$	1,115
Cost of products sold	14,832		14,384		448
Segment margin	3,615		2,948		667
Unrealized (gains) losses on commodity risk management activities	(69)		55		(124)
Operating expenses, excluding non-cash compensation expense	(570)		(547)		(23)
Selling, general and administrative expenses, excluding non-cash compensation expense	(85)		(86)		1
Adjusted EBITDA related to unconsolidated affiliates	8		15		(7)
Other	(1)		—		(1)
Segment Adjusted EBITDA	$	2,898	$	2,385	$	513

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

•an increase of $543 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $282 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region and contributions from capacity expansion projects placed into service, a $219 million increase in throughput on our Bakken pipeline, a favorable change due to inventory valuation adjustment of $75 million, partially offset by a $90 million reduction due to lower pipeline basis spreads net of hedges. We also realized a $66 million increase from higher volumes on our Bayou Bridge Pipeline, a $31 million increase due to the inclusion of assets acquired in 2019, and a $26 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland terminal; partially offset by a $54 million decrease from our Oklahoma assets resulting from lower volumes to the system as well as from the timing of a deficiency payment made in the prior year, a $12 million decrease due to the closure of a third party refinery which was the primary customer utilizing one of our northeast crude terminals. The remainder of the offsetting decrease was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period; partially offset by

•an increase of $23 million in operating expenses primarily due to a $30 million increase in throughput-related costs on existing assets, partially offset by a $14 million decrease in management fees as well as the impact of certain intrasegment transactions discussed above; and

•a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.

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Investment in Sunoco LP


	Years Ended December 31,
	2019		2018		Change
Revenues	$	16,596	$	16,994	$	(398)
Cost of products sold	15,380		15,872		(492)
Segment margin	1,216		1,122		94
Unrealized (gains) losses on commodity risk management activities	(5)		6		(11)
Operating expenses, excluding non-cash compensation expense	(365)		(435)		70
Selling, general and administrative, excluding non-cash compensation expense	(123)		(129)		6
Adjusted EBITDA related to unconsolidated affiliates	4		—		4
Inventory valuation adjustments	(79)		85		(164)
Adjusted EBITDA from discontinued operations	—		(25)		25
Other, net	17		14		3
Segment Adjusted EBITDA	$	665	$	638	$	27

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:

•a decrease in operating costs of $76 million, primarily as a result of the conversion of 207 retail sites to commission agent sites during April 2018. These expenses include other operating expense, general and administrative expense and lease expense; and

•an increase of $25 million related to Adjusted EBITDA from discontinued operations related to the divestment of 1,030 company-operated fuel sites to 7-Eleven in January 2018; and

•an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by

•a decrease in the gross profit on motor fuel sales of $76 million (excluding the change in inventory fair value adjustments and unrealized gains and losses on commodity risk management activities) primarily due to lower fuel margins, a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier recorded in 2018 and an $8 million one-time charge related to a reserve for an open contractual dispute recorded in 2019, partially offset by an increase in gallons sold.

Investment in USAC


	Years Ended December 31,
	2019		2018		Change
Revenues	$	698	$	508	$	190
Cost of products sold	91		67		24
Segment margin	607		441		166

Operating expenses, excluding non-cash compensation expense	(134)		(110)		(24)
Selling, general and administrative, excluding non-cash compensation expense	(53)		(50)		(3)



Other, net	—		8		(8)
Segment Adjusted EBITDA	$	420	$	289	$	131

The investment in USAC segment reflects the consolidated results of USAC from April 2, 2018, the date ET obtained control of USAC. Changes between periods are primarily due to the consolidation of USAC beginning April 2, 2018.

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All Other


	Years Ended December 31,
	2019		2018		Change
Revenue	$	1,689	$	2,228	$	(539)
Cost of products sold	1,504		2,006		(502)
Segment margin	185		222		(37)
Unrealized gains on commodity risk management activities	(4)		(2)		(2)
Operating expenses, excluding non-cash compensation expense	(77)		(56)		(21)
Selling, general and administrative expenses, excluding non-cash compensation expense	(58)		(87)		29
Adjusted EBITDA related to unconsolidated affiliates	2		1		1
Other and eliminations	58		(2)		60
Segment Adjusted EBITDA	$	106	$	76	$	30

Amounts reflected in our all other segment primarily include:

•our natural gas marketing operations;

•our wholly-owned natural gas compression operations;

•a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate; and

•our investment in coal handling facilities;

•our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA increased due to the net impacts of the following:

•an increase of $8 million in gains from park and loan and storage activity;

•an increase of $11 million in optimized gains on residue gas sales;

•an increase of $7 million from settled derivatives;

•an increase of $15 million from a legal settlement;

•an increase of $12 million from payments related to the PES bankruptcy;

•an increase of $6 million from the recognition of deferred revenue related to a bankruptcy;

•an increase of $3 million from power trading activities;

•an increase of $3 million from the SemCAMS joint venture for the period subsequent to our acquisition of SemGroup on December 5, 2019, net of an increase due to SemGroup related corporate expenses; and

•a decrease of $21 million in merger and acquisition expenses; partially offset by

•a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;

•a decrease of $8 million due to lower gas prices and increased power costs; and

•a decrease of $11 million due to lower revenue from our compressor equipment business.

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Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017

Consolidated Results


	Years Ended December 31,
	2018		2017		Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	927	$	626	$	301
Interstate transportation and storage	1,680		1,274		406
Midstream	1,627		1,481		146
NGL and refined products transportation and services	1,979		1,641		338
Crude oil transportation and services	2,385		1,328		1,057
Investment in Sunoco LP	638		732		(94)
Investment in USAC	289		—		289
All other	76		219		(143)
Total	9,601		7,301		2,300
Depreciation, depletion and amortization	(2,843)		(2,541)		(302)
Interest expense, net of interest capitalized	(1,709)		(1,575)		(134)
Impairment losses	(431)		(1,039)		608
Gains (losses) on interest rate derivatives	47		(37)		84
Non-cash compensation expense	(105)		(99)		(6)
Unrealized gains (losses) on commodity risk management activities	(11)		59		(70)
Inventory valuation adjustments	(85)		24		(109)
Losses on extinguishments of debt	(109)		(42)		(67)
Adjusted EBITDA related to unconsolidated affiliates	(655)		(716)		61
Equity in earnings of unconsolidated affiliates	344		144		200
Impairment of investments in unconsolidated affiliates	—		(313)		313
Adjusted EBITDA related to discontinued operations	25		(223)		248
Other, net	30		154		(124)
Income from continuing operations before income tax (expense) benefit	4,099		1,097		3,002
Income tax (expense) benefit from continuing operations	(5)		1,804		(1,809)
Income from continuing operations	4,094		2,901		1,193
Loss from discontinued operations, net of income taxes	(265)		(177)		(88)
Net income	$	3,829	$	2,724	$	1,105

Adjusted EBITDA (consolidated). For the year ended December 31, 2018 compared to the prior year, Adjusted EBITDA increased approximately $2.3 billion, or 32%. The increase was primarily due to the impact of multiple revenue-generating assets being placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets and acquisitions was approximately $1.2 billion, of which the largest increases were from the Bakken pipeline (a $546 million impact to the crude oil transportation and services segment), the Rover pipeline (a $359 million impact to the interstate transportation and storage segment) and the acquisition of USAC (a net impact of $191 million among the investment in USAC and all other segments). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, particularly due to increased production in the Permian, which impacted multiple segments. Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.

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Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased during the year ended December 31, 2018 compared to December 31, 2017 primarily due to the following:

•an increase of $121 million recognized by the Partnership primarily related to an increase in long-term debt, including additional senior note issuances and borrowings under our revolving credit facilities; and

•an increase of $78 million due to the acquisition of USAC on April 2, 2018; offset by

•a decrease of $65 million recognized by Sunoco LP primarily due to the repayment in full of its term loan and lower interest rates on its senior notes as a result of Sunoco LP’s January 23, 2018 issuance of senior notes which paid off in full Sunoco LP’s previously outstanding senior notes which had higher interest rates.

Impairment Losses. During the year ended December 31, 2018, the Partnership recognized goodwill impairments of $378 million and asset impairments of $4 million related to our midstream operations and asset impairments of $9 million related to our crude operations idle leased assets. Sunoco LP recognized a $30 million indefinite-lived intangible impairment related to its contractual rights. USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets.

During the year ended December 31, 2017, the Partnership recorded goodwill impairments of $223 million related to the compression business, $229 million related to Panhandle, $262 million related to the interstate transportation and storage segment and $79 million related to the NGL and refined products transportation and services segment. Sunoco LP recognized goodwill impairments of $387 million in 2017, of which $102 million was allocated to continuing operations. In addition, during the year ended December 31, 2017, the Partnership recorded an impairment to the property, plant and equipment of Sea Robin of $127 million. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.

Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Gains (losses) on interest rate derivatives during the years ended December 31, 2018 and 2017 resulted from an increase in forward interest rates in 2018 and a decrease in forward interest rates in 2017, which caused our forward-starting swaps to change in value.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See discussion of the unrealized gains (losses) on commodity risk management activities included in “Segment Operating Results” below.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP as a result of commodity price changes between periods.

Impairment of Investments in Unconsolidated Affiliates. During the year ended December 31, 2017, the Partnership recorded impairments to its investments in FEP of $141 million and HPC of $172 million. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.

Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that were disposed of in January 2018.

Other, net. Other, net in 2018 and 2017 primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax (Expense) Benefit. On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.78 billion in December 2017. For the year ended December 2018, the Partnership recorded an income tax expense due to pre-tax income at its corporate subsidiaries, partially offset by a statutory rate reduction.

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Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:


	Years Ended December 31,
	2018		2017		Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	141	$	144	$	(3)
FEP	55		53		2
MEP	31		38		(7)
HPC (1)(2)	3		(168)		171
Other	114		77		37
Total equity in earnings of unconsolidated affiliates	$	344	$	144	$	200

Adjusted EBITDA related to unconsolidated affiliates(3):
Citrus	$	337	$	336	$	1
FEP	74		74		—
MEP	81		88		(7)
HPC (2)	9		46		(37)
Other	154		172		(18)
Total Adjusted EBITDA related to unconsolidated affiliates	$	655	$	716	$	(61)

Distributions received from unconsolidated affiliates:
Citrus	$	171	$	156	$	15
FEP	68		47		21
MEP	48		114		(66)
HPC (2)	—		35		(35)
Other	110		80		30
Total distributions received from unconsolidated affiliates	$	397	$	432	$	(35)

(1)The partnership previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, we acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in our financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in our financial statements.

(2)For the year ended December 31, 2017, equity in earnings of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

(3)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

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Segment Operating Results

Intrastate Transportation and Storage


	Years Ended December 31,
	2018		2017		Change
Natural gas transported (BBtu/d)	10,873		8,760		2,113
Revenues	$	3,737	$	3,083	$	654
Cost of products sold	2,665		2,327		338
Segment margin	1,072		756		316
Unrealized (gains) losses on commodity risk management activities	38		(5)		43
Operating expenses, excluding non-cash compensation expense	(189)		(168)		(21)
Selling, general and administrative, excluding non-cash compensation expense	(27)		(22)		(5)
Adjusted EBITDA related to unconsolidated affiliates	32		64		(32)
Other	1		1		—
Segment Adjusted EBITDA	$	927	$	626	$	301

Volumes. For the year ended December 31, 2018 compared to the prior year, transported volumes increased primarily due to favorable market pricing spreads, as well as the impact of reflecting RIGS assets as a consolidated subsidiary beginning in April 2018.

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:


	Years Ended December 31,
	2018		2017		Change
Transportation fees	$	525	$	448	$	77
Natural gas sales and other (excluding unrealized gains and losses)	510		196		314
Retained fuel revenues (excluding unrealized gains and losses)	59		58		1
Storage margin, including fees (excluding unrealized gains and losses)	16		49		(33)
Unrealized gains (losses) on commodity risk management activities	(38)		5		(43)
Total segment margin	$	1,072	$	756	$	316

Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:

•an increase of $314 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity;

•a net increase of $14 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $73 million, $16 million and $6 million, respectively, and a decrease of $37 million in Adjusted EBITDA related to unconsolidated affiliates; and

•an increase of $4 million in transportation fees, excluding the impact of consolidating RIGS as discussed above, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; partially offset by

•a decrease of $33 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory, lower storage fees and lower realized derivative gains.

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Interstate Transportation and Storage


	Years Ended December 31,
	2018		2017		Change
Natural gas transported (BBtu/d)	9,542		6,058		3,484
Natural gas sold (BBtu/d)	17		18		(1)
Revenues	$	1,682	$	1,131	$	551
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(431)		(315)		(116)
Selling, general and administrative, excluding non-cash compensation, amortization and accretion expenses	(63)		(41)		(22)
Adjusted EBITDA related to unconsolidated affiliates	492		498		(6)
Other	—		1		(1)
Segment Adjusted EBITDA	$	1,680	$	1,274	$	406

Volumes. For the year ended December 31, 2018 compared to the prior year, transported volumes reflected increases of 1,919 BBtu/d as a result of the initiation of service on the Rover pipeline; increases of 572 BBtu/d and 439 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to higher demand resulting from colder weather and increased utilization by the Rover pipeline; 375 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale, and 145 BBtu/d on the Transwestern pipeline resulting from favorable market opportunities in the West, midcontinent and Waha areas from the Permian supply basin.

Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:

•an increase of $359 million associated with the Rover pipeline with increases of $485 million in revenues, $105 million in net operating expenses and $21 million in selling, general and administrative expenses and other; and

•an aggregate increase of $66 million in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines; partially offset by

•an increase of $11 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to increases in maintenance project costs due to scope and level of activity; and

•a decrease of $6 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower margins on MEP due to lower rates on renewals of expiring long term contracts.

Midstream


	Years Ended December 31,
	2018		2017		Change
Gathered volumes (BBtu/d):	12,126		10,956		1,170
NGLs produced (MBbls/d):	540		472		68
Equity NGLs (MBbls/d):	29		27		2
Revenues	$	7,522	$	6,943	$	579
Cost of products sold	5,145		4,761		384
Segment margin	2,377		2,182		195
Unrealized gains on commodity risk management activities	—		(15)		15
Operating expenses, excluding non-cash compensation expense	(705)		(638)		(67)
Selling, general and administrative, excluding non-cash compensation expense	(81)		(78)		(3)
Adjusted EBITDA related to unconsolidated affiliates	33		28		5
Other	3		2		1
Segment Adjusted EBITDA	$	1,627	$	1,481	$	146

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Volumes. Gathered volumes and NGL production increased during the year ended December 31, 2018 compared to the prior year primarily due to increases in the North Texas, Permian and Northeast regions, partially offset by smaller declines in other regions.

Segment Margin. The table below presents the components of our midstream segment margin. For the years ended December 31, 2018 and 2017, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees from fee-based margin to non-fee-based margin in order to conform to the current period classification.


	Years Ended December 31,
	2018		2017		Change
Gathering and processing fee-based revenues	$	1,788	$	1,690	$	98
Non-fee based contracts and processing (excluding unrealized gains and losses)	589		477		112
Unrealized gains on commodity risk management activities	—		15		(15)
Total segment margin	$	2,377	$	2,182	$	195

Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:

•an increase of $98 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions;

•an increase of $79 million in non fee-based margin due to increased throughput volume in the North Texas and Permian regions;

•an increase of $33 million in non fee-based margin due to higher crude oil and NGL prices; and

•an increase of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by

•an increase of $67 million in operating expenses primarily due to increases of $20 million in outside services, $19 million in materials, $8 million in maintenance project costs, $7 million in ad valorem taxes, $6 million in employee costs and $6 million in office expenses; and

•an increase of $3 million in selling, general and administrative expenses due to higher professional fees.

NGL and Refined Products Transportation and Services


	Years Ended December 31,
	2018		2017		Change
NGL transportation volumes (MBbls/d)	1,027		863		164
Refined products transportation volumes (MBbls/d)	621		624		(3)
NGL and refined products terminal volumes (MBbls/d)	812		783		29
NGL fractionation volumes (MBbls/d)	527		427		100
Revenues	$	11,123	$	8,648	$	2,475
Cost of products sold	8,462		6,508		1,954
Segment margin	2,661		2,140		521
Unrealized gains on commodity risk management activities	(86)		(26)		(60)
Operating expenses, excluding non-cash compensation expense	(604)		(478)		(126)
Selling, general and administrative expenses, excluding non-cash compensation expense	(74)		(64)		(10)
Adjusted EBITDA related to unconsolidated affiliates	82		68		14
Other	—		1		(1)
Segment Adjusted EBITDA	$	1,979	$	1,641	$	338

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Volumes. For the year ended December 31, 2018 compared to the prior year, NGL transportation volumes increased primarily due to increased volumes from the Permian region resulting from a ramp up in production from existing customers, higher throughput volumes on Mariner West driven by end-user facility constraints in the prior year and higher throughput from Mariner South resulting from increased export volumes.

Refined products transportation volumes decreased for the year ended December 31, 2018 compared to prior year, primarily due to timing of turnarounds at third-party refineries in the Midwest and Northeast regions.

NGL and Refined products terminal volumes increased for the year ended December 31, 2018 compared to prior year, primarily due to more volumes loaded at our Nederland terminal as propane export demand increased and higher throughput volumes at our refined products terminals in the Northeast.

Average volumes fractionated at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2018 compared to the prior year primarily due to increased volumes from the Permian region, as well as an increase in fractionation capacity as our fifth fractionator at Mont Belvieu came online in July 2018.

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:


	Years Ended December 31,
	2018		2017		Change
Fractionators and refinery services margin	$	511	$	415	$	96
Transportation margin	1,233		990		243
Storage margin	211		214		(3)
Terminal Services margin	494		424		70
Marketing margin	126		71		55
Unrealized gains on commodity risk management activities	86		26		60
Total segment margin	$	2,661	$	2,140	$	521

Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

•an increase in transportation margin of $243 million primarily due to a $216 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, a $31 million increase due to higher throughput volumes on Mariner West driven by end-user facility constraints in the prior period, a $15 million increase resulting from a reclassification between our transportation and fractionation margins, a $9 million increase due to higher throughput volumes from the Barnett region, a $5 million increase due to higher throughput volumes on Mariner South due to system downtime in the prior period and a $4 million increase in prior period customer credits. These increases were partially offset by a $16 million decrease resulting from lower throughput volumes on Mariner East 1 due to system downtime in 2018, a $14 million decrease due to lower throughput volumes from the Southeast Texas region and a $7 million decrease resulting from the timing of deficiency fee revenue recognition;

•an increase in fractionation and refinery services margin of $96 million primarily due to a $106 million increase resulting from the commissioning of our fifth fractionator in July 2018 and a $7 million increase from blending gains as a result of improved market pricing. These increases were partially offset by a $16 million decrease resulting from a reclassification between our transportation and fractionation margins and a $2 million decrease from higher affiliate storage fees paid;

•an increase in terminal services margin of $70 million due to a $36 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $23 million increase at our Nederland terminal due to increased export demand and a $12 million increase due to higher throughput at our Marcus Hook Industrial Complex. These increases were partially offset by lower terminal throughput fees in part due to the sale of one of our terminals in April 2017;

•an increase in marketing margin of $55 million due to a $48 million increase from our butane blending operations and a $22 million increase in sales of NGLs and other products at our Marcus Hook Industrial Complex due to more favorable market prices. These increases were partially offset by a $15 million decrease from the timing of optimization gains from our Mont Belvieu fractionators; and

•an increase of $14 million to adjusted EBITDA related to unconsolidated affiliates due to improved contributions from our unconsolidated refined products joint venture interests; partially offset by

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•an increase of $126 million in operating expenses primarily due to a $30 million increase in costs to operate our fractionators and a $20 million increase in operating costs on our NGL pipelines as a result of higher throughput and the commissioning of our fifth fractionator in July 2018, a $36 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, increases of $24 million and $7 million to operating costs at our Marcus Hook and Nederland terminals, respectively, as a result of significantly higher volumes through both terminals in 2018, an $8 million increase to environmental reserves and a $1 million increase to overhead allocations and maintenance repairs performed on our refinery services assets; and

•an increase of $10 million in selling, general and administrative expenses primarily due to a $6 million increase in overhead costs allocated to the segment, a $2 million increase in legal fees, a $1 million increase in management fees previously recorded in operating expenses and a $1 million increase in employee costs.

Crude Oil Transportation and Services


	Years Ended December 31,
	2018		2017		Change
Crude transportation volumes (MBbls/d)	4,172		3,538		634
Crude terminals volumes (MBbls/d)	2,096		1,928		168
Revenue	$	17,332	$	11,703	$	5,629
Cost of products sold	14,384		9,877		4,507
Segment margin	2,948		1,826		1,122
Unrealized losses on commodity risk management activities	55		1		54
Operating expenses, excluding non-cash compensation expense	(547)		(430)		(117)
Selling, general and administrative expenses, excluding non-cash compensation expense	(86)		(82)		(4)
Adjusted EBITDA related to unconsolidated affiliates	15		13		2

Segment Adjusted EBITDA	$	2,385	$	1,328	$	1,057

Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

•an increase of $1.18 billion in segment margin (excluding unrealized losses on commodity risk management activities) primarily due to the following: a $586 million increase resulting from placing the Bakken pipeline in service in the second quarter of 2017, a $266 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers; and gains of $280 million due to more favorable basis spreads; partially offset by an unfavorable change due to inventory valuation adjustment of $122 million; and

•an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to increased jet fuel sales from our joint ventures; partially offset by

•an increase of $117 million in operating expenses primarily due to a $67 million increase to throughput related costs on existing assets; a $36 million increase resulting from placing the Bakken pipeline in service in the second quarter of 2017; a $26 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $5 million increase from ad valorem taxes; partially offset by an $17 million decrease in insurance and environmental related expenses; and

•an increase of $4 million in selling, general and administrative expenses primarily due to increases associated with placing our Bakken Pipeline in service in the second quarter of 2017.

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Investment in Sunoco LP


	Years Ended December 31,
	2018		2017		Change
Revenues	$	16,994	$	11,723	$	5,271
Cost of products sold	15,872		10,615		5,257
Segment margin	1,122		1,108		14
Unrealized (gains) losses on commodity risk management activities	6		(3)		9
Operating expenses, excluding non-cash compensation expense	(435)		(456)		21
Selling, general and administrative, excluding non-cash compensation expense	(129)		(116)		(13)

Inventory valuation adjustments	85		(24)		109
Adjusted EBITDA from discontinued operations	(25)		223		(248)
Other, net	14		—		14
Segment Adjusted EBITDA	$	638	$	732	$	(94)

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment decreased due to the net impacts of the following:

•a decrease of $248 million in Adjusted EBITDA from discontinued operations primarily due to Sunoco LP’s retail divestment in January 2018; partially offset by

•an increase of $109 million in inventory fair value adjustments due to changes in fuel prices between periods;

•an increase of $14 million in margin primarily due to an increase in rental income as a result of the increase in commission agent sites in the current year, offset by decreases in the gross profit on motor fuel sales; and

•a net decrease of $8 million in operating and selling, general and administrative expenses primarily due to decreased rent expense.

Investment in USAC


	Years Ended December 31,
	2018		2017		Change
Revenues	$	508	$	—	$	508
Cost of products sold	67		—		67
Segment margin	441		—		441

Operating expenses, excluding non-cash compensation expense	(110)		—		(110)
Selling, general and administrative, excluding non-cash compensation expense	(50)		—		(50)



Other, net	8		—		8
Segment Adjusted EBITDA	$	289	$	—	$	289

The investment in USAC segment reflects the consolidated results of USAC from April 2, 2018, the date ET obtained control of USAC, through December 31, 2018. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.

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All Other


	Years Ended December 31,
	2018		2017		Change
Revenue	$	2,228	$	2,901	$	(673)
Cost of products sold	2,006		2,509		(503)
Segment margin	222		392		(170)
Unrealized gains on commodity risk management activities	(2)		(11)		9
Operating expenses, excluding non-cash compensation expense	(56)		(117)		61
Selling, general and administrative expenses, excluding non-cash compensation expense	(87)		(103)		16
Adjusted EBITDA related to unconsolidated affiliates	1		45		(44)

Other and eliminations	(2)		13		(15)
Segment Adjusted EBITDA	$	76	$	219	$	(143)

Amounts reflected in our all other segment during the periods presented above primarily include:

•our natural gas marketing operations;

•our wholly-owned natural gas compression operations;

•a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETO holds an approximately 8% interest in PES and no longer reflects PES as an affiliate; and

•our investment in coal handling facilities.

Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA decreased due to the net impacts of the following:

•a decrease of $98 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;

•a decrease of $38 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES primarily due to our lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018;

•a decrease of $4 million due to merger and acquisition expenses related to the Energy Transfer Merger in 2018; and

•a decrease of $15 million due to a one-time fee received from a joint venture affiliate in 2017; partially offset by

•an increase of $7 million due to lower transport fees resulting from the expiration of a capacity commitment on Trunkline pipeline;

•an increase of $6 million due to a decrease in losses from mark-to-market of physical system gas; and

•an increase of $7 million due to increased margin from ETO’s compression equipment business.

Liquidity and Capital Resources

Our ability to satisfy our obligations and pay distributions to our preferred unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

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As of February 21, 2020, the Partnership expected capital expenditures in 2020 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):


	Growth				Maintenance
	Low		High		Low		High
Intrastate transportation and storage	$	20	$	30	$	40	$	45
Interstate transportation and storage (1)	100		125		140		145
Midstream	625		650		125		130
NGL and refined products transportation and services (1)	2,550		2,650		100		110
Crude oil transportation and services	500		525		165		175
All other (including eliminations)	125		150		75		80
Total capital expenditures	$	3,920	$	4,130	$	645	$	685

(1)Includes capital expenditures related to our proportionate ownership of the Bakken, Rover, and Bayou Bridge pipeline projects and our proportionate ownership of the Orbit Gulf Coast NGL export project.

The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we include these factors in our anticipated growth capital expenditures for each year.

We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally expect to fund growth capital expenditures with proceeds of borrowings under ETO credit facilities, along with cash from operations.

As of December 31, 2019, in addition to $288 million of cash on hand, we had available capacity under the ETO Credit Facilities of $1.71 billion. Based on our current estimates, we expect to utilize capacity under the ETO Credit Facilities, along with cash from operations, to fund our announced growth capital expenditures and working capital needs through the end of 2020; however, we may issue debt or equity securities prior to that time as we deem prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.

Sunoco LP

Sunoco LP’s primary sources of liquidity consist of cash generated from operating activities, borrowings under its $1.50 billion credit facility and the issuance of additional long-term debt or partnership units as appropriate given market conditions. At December 31, 2019, Sunoco LP had available borrowing capacity of $1.33 billion under its revolving credit facility and $21 million of cash and cash equivalents on hand.

In 2020, Sunoco LP expects to invest approximately $130 million in growth capital expenditures and approximately $45 million on maintenance capital expenditures. Sunoco LP may revise the timing of these expenditures as necessary to adapt to economic conditions.

USAC

USAC currently plans to spend approximately $32 million in maintenance capital expenditures during 2020, including parts consumed from inventory.

Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between $110 million and $120 million in expansion capital expenditures during 2020. As of December 31, 2019, USAC has binding commitments to purchase $49 million of additional compression units, all of which USAC expects to be delivered in 2020.

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Cash Flows

Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price of our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.

Following is a summary of operating activities by period:

Year Ended December 31, 2019

Cash provided by operating activities in 2019 was $8.25 billion and income from continuing operations was $5.12 billion. The difference between net income and cash provided by operating activities in 2019 primarily consisted of non-cash items totaling $3.30 billion offset by net changes in operating assets and liabilities of $448 million. The non-cash activity in 2019 consisted primarily of depreciation, depletion and amortization of $3.14 billion, impairment losses of $74 million, non-cash compensation expense of $113 million, equity in earnings of unconsolidated affiliates of $302 million, inventory valuation adjustments of $79 million, losses on extinguishment of debt of $2 million, and deferred income tax expense of $221 million. The Partnership also received distributions of $290 million from unconsolidated affiliates.

Year Ended December 31, 2018

Cash provided by operating activities in 2018 was $7.56 billion and income from continuing operations was $4.09 billion. The difference between net income and cash provided by operating activities in 2018 primarily consisted of non-cash items totaling $3.11 billion offset by net changes in operating assets and liabilities of $62 million. The non-cash activity in 2018 consisted primarily of depreciation, depletion and amortization of $2.84 billion, impairment losses of $431 million, non-cash compensation expense of $105 million, equity in earnings of unconsolidated affiliates of $344 million, inventory valuation adjustments of $85 million, losses on extinguishment of debt of $109 million and a deferred income tax expense of $8 million. The Partnership also received distributions of $328 million from unconsolidated affiliates.

Year Ended December 31, 2017

Cash provided by operating activities in 2017 was $4.82 billion and income from continuing operations was $2.90 billion. The difference between net income and cash provided by operating activities in 2017 primarily consisted of non-cash items totaling $1.78 billion offset by net changes in operating assets and liabilities of $122 million. The non-cash activity in 2017 consisted primarily of depreciation, depletion and amortization of $2.54 billion, impairment losses of $1.04 billion, impairment in unconsolidated affiliates of $313 million, non-cash compensation expense of $99 million, equity in earnings of unconsolidated affiliates of $144 million, inventory valuation adjustments of $24 million, losses on extinguishment of debt of $42 million and a deferred income tax benefit of $1.84 billion. The Partnership also received distributions of $297 million from unconsolidated affiliates.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

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Following is a summary of investing activities by period:

Year Ended December 31, 2019

Cash used in investing activities in 2019 was $6.40 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $5.88 billion. Additional detail related to our capital expenditures is provided in the table below. During 2019, we received $93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary, paid $250 million in net cash for the SemGroup acquisition, and paid $7 million in cash for all other acquisitions. We received $54 million of cash proceeds from the sale of assets. The Partnership also received distributions of $98 million from unconsolidated affiliates.

Year Ended December 31, 2018

Cash used in investing activities in 2018 was $6.90 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $7.30 billion. Additional detail related to our capital expenditures is provided in the table below. We received $711 million of net cash proceeds related to the USAC acquisition and paid $429 million in cash for all other acquisitions. We received $87 million of cash proceeds from the sale of assets. The Partnership also received distributions of $69 million from unconsolidated affiliates.

Year Ended December 31, 2017

Cash used in investing activities in 2017 was $5.61 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $8.42 billion. Additional detail related to our capital expenditures is provided in the table below. We paid $280 million in cash related to the acquisition of PennTex’s remaining noncontrolling interest and $303 million in cash for all other acquisitions. We received $2.00 billion in cash related to the Bakken equity sale to MarEn Bakken Company LLC, $1.48 billion in cash related to the Rover equity sale to Blackstone Capital Partners. We received $45 million of cash proceeds from the sale of assets. The Partnership also received distributions of $135 million from unconsolidated affiliates.

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The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, and Bayou Bridge pipeline projects, our proportionate share of the Orbit Gulf Coast NGL export project, and net of contributions in aid of construction costs) by period:


	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Year Ended December 31, 2019:
Intrastate transportation and storage	$	87	$	37	$	124
Interstate transportation and storage	239		136		375
Midstream	670		157		827
NGL and refined products transportation and services	2,854		122		2,976
Crude oil transportation and services	317		86		403
Investment in Sunoco LP	108		40		148
Investment in USAC	170		30		200
All other (including eliminations)	165		50		215
Total capital expenditures	$	4,610	$	658	$	5,268

Year Ended December 31, 2018:
Intrastate transportation and storage	$	311	$	33	$	344
Interstate transportation and storage	695		117		812
Midstream	1,026		135		1,161
NGL and refined products transportation and services	2,303		78		2,381
Crude oil transportation and services	414		60		474
Investment in Sunoco LP (1)	72		31		103
Investment in USAC	182		23		205
All other (including eliminations)	117		33		150
Total capital expenditures	$	5,120	$	510	$	5,630

Year Ended December 31, 2017:
Intrastate transportation and storage	$	155	$	20	$	175
Interstate transportation and storage	645		83		728
Midstream	1,185		123		1,308
NGL and refined products transportation and services	2,899		72		2,971
Crude oil transportation and services	392		61		453
Investment in Sunoco LP (1)	129		48		177
All other (including eliminations)	196		72		268
Total capital expenditures	$	5,601	$	479	$	6,080

(1)Amounts related to Sunoco LP’s capital expenditures include capital expenditures related to discontinued operations.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions to partners increased between the periods as a result of increases in the number of common units outstanding.

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Following is a summary of financing activities by period:

Year Ended December 31, 2019

Cash used in financing activities was $1.98 billion in 2019. During 2019, we received net proceeds of $780 million from the issuance of preferred units. Net proceeds from the offering were used to repay outstanding borrowings under the ETO Credit Facilities, to fund capital expenditures and acquisitions, as well as for general partnership purposes. In 2019, we had a net increase in in our debt level of $4.70 billion. In 2019, we paid distributions of $6.28 billion to our partners and we paid distributions of $1.40 billion to noncontrolling interests. In addition, we received capital contributions of $348 million in cash from noncontrolling interests. During 2019, we incurred debt issuance costs of $117 million.

Year Ended December 31, 2018

Cash used in financing activities was $3.31 billion in 2018. During 2018, we received $58 million in net proceeds from common unit offerings and $867 million in net proceeds from the issuance of preferred units. Net proceeds from the offerings were used to repay outstanding borrowings under the ETO Credit Facility, to fund capital expenditures and acquisitions as well as for general partnership purposes. In 2018, we had a net increase in our debt level of $801 million. In 2018, we paid distributions of $4.56 billion to our partners and distributions of $1.17 billion to noncontrolling interests, including predecessor distributions. During 2018, we incurred debt issuance costs of $162 million, and our subsidiaries repurchased $300 million of common units in cash. In addition, we received capital contributions from noncontrolling interests of $649 million. Additionally, in 2018, our subsidiary received $465 million related to redeemable noncontrolling interests.

Year Ended December 31, 2017

Cash provided by financing activities was $572 million in 2017. We received $2.28 billion in net proceeds from common unit offerings, $1.48 billion in net proceeds from the issuance of preferred units and we received $333 million in net proceeds from predecessor equity offerings. Net proceeds from the offerings and issuances were used to repay outstanding borrowings under the ETO Credit Facility, to fund capital expenditures and acquisitions as well as for general partnership purposes. In 2017, we had a net decrease in our debt level of $421 million. In addition, we incurred debt issuance costs of $83 million. In 2017, we paid distributions of $3.47 billion to our partners and distributions of $714 million to noncontrolling interests, including predecessor distributions. In addition, we received capital contributions from noncontrolling interests of $1.21 billion.

Discontinued Operations

Cash flows from discontinued operations reflect cash flows related to Sunoco LP’s retail divestment.

Year Ended December 31, 2019

There were no cash flows related to discontinued operations during 2019.

Year Ended December 31, 2018

Cash provided by discontinued operations was $2.73 billion for the year ended December 31, 2018 resulting from cash used in operating activities of $484 million, cash provided by investing activities of $3.21 billion, and changes in cash included in current assets held for sale of $11 million.

Year Ended December 31, 2017

Cash provided by discontinued operations was $93 million for the year ended December 31, 2017 resulting from cash provided by operating activities of $136 million, cash used in investing activities of $38 million, and changes in cash included in current assets held for sale of $5 million.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	December 31,
	2019		2018
ETO Senior Notes	$	36,118	$	28,755
Transwestern Senior Notes	575		575
Panhandle Senior Notes	235		385
Bakken Senior Notes	2,500		—
Sunoco LP Senior Notes, Term Loan and lease-related obligations	2,935		2,307
USAC Senior Notes	1,475		725
Revolving credit facilities:
ETO $2.00 billion Term Loan facility due October 2022	2,000		—
ETO $5.00 billion Revolving Credit Facility due December 2023	4,214		3,694

Sunoco LP $1.50 billion Revolving Credit Facility due July 2023	162		700
USAC $1.60 billion Revolving Credit Facility due April 2023	403		1,050
Bakken $2.50 billion Credit Facility due August 2019	—		2,500
HFOTCO Tax Exempt Notes due 2050	225		—
SemCAMS Revolver due February 2024	92		—
SemCAMS Term Loan A due February 2024	269		—
Other long-term debt	2